Capture of CO2 From Hydrogen Plants

ABSTRACT

The invention includes a process which eliminates or reduces the CO 2  emissions from a steam methane reforming and autothermal reforming plant. The process preferentially uses temperature swing adsorption units which are employed to purify the hydrogen stream instead of more conventional solvent based aMDEA plants to remove the CO 2  from the gas stream when creating a higher purity hydrogen stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit under 35 USC 119 of U.S. Provisional Patent Application No. 61/747,746 with a filing date of Dec. 31, 2012. In addition, application Ser. No. 61/747,778, filed on Dec. 31, 2012 is also incorporated herein by reference for all purposes.

FIELD OF THE INVENTION

The invention relates to the field of capturing CO₂ from a hydrogen plant and in particular capturing CO₂ from a process that produces hydrogen for use as a fuel or in petroleum or chemical operations.

BACKGROUND OF THE INVENTION

Steam methane reformer (SMR) plants often a widely employed in refineries to supply H₂ for various product upgrading operations. The SMR process produces a large amount of CO₂ which must be cleaned from hydrogen stream. In steam methane reformer plants and solvent based aMDEA is used to remove the CO₂ from the hydrogen stream. Newer conventional hydrogen plants may use pressure swing adsorption (PSA) units to purify the CO₂ from the hydrogen stream. In both these units large amounts of CO₂ at low concentration and pressure are emitted from the SMR furnace. Capture of this CO₂ using a post combustion amine based technology such as aMDEA is expensive. Autothermal reformer (ATR) units may be used to produce CO₂-free hydrogen at reduced costs. However, they require expensive air separation unit (ASU) to produce the oxygen. Also, the ASU requires a large amount of power, which itself results in additional CO₂ emissions.

A recent patent application US 2010/0080754 teaches a method of reducing the CO₂ emissions from the steam methane reformer plant by employing a temperature swing adsorption (TSA) unit in place of a traditional PSA unit. After the shift reactors, the fuel gas stream is sent to an aMDEA unit to remove majority of the CO₂ In the gas stream. The CO₂-free fuel gas stream is next sent to a TSA unit, which produces high-purity H₂ by adsorbing CO, CH₄ and any remaining CO₂ on an adsorbent. The TSA adsorbent bed is next regenerated by using high pressure and high temperature natural gas and steam and the off-gas is sent to the steam methane reformer as a high pressure feed. The steam methane reformer furnace is fueled by a portion of the pure hydrogen product. The patent, however, does not address how to reduce CO₂ emissions from an SMR plant that does not have an amine absorber upstream of the TSA unit.

SUMMARY OF THE INVENTION

The instant process is described vs. need to eliminate or substantially reduce the CO₂ emissions from reforming plants to address the global warming resulting from CO₂ emissions.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process schematic of the steam methane reforming (SMR) process according to the invention.

FIG. 2 is a more detailed illustration of a TSA unit 120 identified as 220 in FIG. 1 and sweeping with a CH₄ stream.

FIG. 3 is a more detailed illustration of a TSA unit 120 in FIG. 1 identified as 320 and sweeping with a H₂ stream.

DETAILED DESCRIPTION OF THE PROCESS

Process will be more particularly described by referring to FIG. 1. Natural gas 104 and steam 102 are introduced into a steam methane reformer (SMR) 106. The volumes of natural gas vary from about 10,000 standard cubic ft per minute to about 2.5 million standard cubic ft per minute and the preferred range is adjusted for specific applications. The steam is introduced at a temperature of from about 300° C. to about 700° C. under a pressure of about 10 bar to about 30 bar. The products from the steam methane reformer 106 are sent to the heat recovery steam generator 112 via line 110. The cold product stream after the recovery of heat in the heat recovery steam generator (HRSG) 112 is sent to the high temperature/low temperature shift reactor 116 via line 114.

Natural gas and steam are sent to the reformer at high pressure from 10 to 30 bar to produce a syngas consisting of H₂+CO+CO₂ and unreacted CH₄ and H₂O. The syngas exiting the reformer is in the range of 800° C.-1100° C., which is cooled in a heat recovery steam generator (HRSG) to a temperature in the range 300° C.-400° C. The CO in the syngas is converted into H₂ using a high temperature water gas shift reaction mechanism known in the art. A low temperature water gas shift may also be used to convert remaining CO into H₂. The syngas stream which now contains greater than 70 vol. % H₂ is sent to a temperature swing adsorption (TSA) unit, which produces a pure H₂ stream at high pressure and the off gases also at high pressure of from about 10 bar to about 30 bar. The first off-gas stream contains primarily CH₄ and CO₂ at high temperature and pressure which is sent to a CO₂ removal process such as an amine, aMDEA or Benfield process, membrane or cryogenic unit for removal of the CO₂. The remainder of the first off-gas stream now contains mostly CH₄ with small amounts of CO. The second off-gas stream contains primarily CH₄ and steam at high pressure and temperature which is combined with the first off-gas stream that is cleaned and sent to the steam methane reformer as feed. Part of the produced H₂ is supplied as feel for the SMR furnace.

Element 120 the temperature swing adsorption element and the process of the invention therein is more particularly described hereinafter.

The first embodiment of the TSA process is described below, in which the adsorbent bed is “swept” in steps with CH₄, H2O and H2 streams as shown in FIG. 2. Any suitable adsorbent known in the art can be used as for example zeolites capable of adsorbing CO₂, CO, and CH₄ and H₂O and the like.

The shifted gas feed 218 enters an adsorbent bed in the TSA illustrated as 220. In Step 1, the adsorbent bed adsorbs 201 a-f all imparity gas components except hydrogen, thus a high purity H₂ stream is obtained at high pressure exiting at 222. Upon saturation of the bed which now consists of the imparities CO₂, CO, and CH₄ and H₂O pins H₂ remaining within the bed voids, in Step 2, hot natural gas at high pressure greater than 20 bar and temperatures in excess of 200 to 300° C. is sent to the bed to remove the CO₂ along with the other components. Depending on the amount of H₂ trapped in the bed void volume, the CO₂ stream may be mixed with a significant amount of H₂. To decrease the amount of H₂ in the CO₂ stream, the initial portion of the exit stream in Step 2 that contains majority of the gases trapped in the void volume (including H₂), is compressed and recycled to be combined with the feed in Step 1. In Step 2, since the bed is still heating up from the low to high temperature, it can be expected that only minor amounts of the adsorbed components are released in the gas stream. Step 2 is optional and depends on the amount of H₂ trapped in the bed void volume. In Step 3, the natural gas “sweep” is continued to release much of the adsorbed CO₂ at the high temperature. The exiting gas stream is termed as the “first” off-gas stream, which primarily contains CH₄ and CO₂, exits via line 224 to a CO₂ removal process unit. Preferably, the CH₄ “sweep” flow rate is adjusted such that the concentration of CO₂ in the “first” off gas stream is in the range of 30 mol %-60 mol %, or more preferably 50 mol %-60 mol %. Although the CO₂ can be removed from other gaseous components using processes such as amine absorption (e.g., aMDEA) or membrane separation, a cryogenic process is preferred which removes CO₂ from other gases by partial condensation, such as those described in U.S. Patent Application Nos. US 2010/0024476, US 2008/0176174, and US 2008/0173585, incorporated herein by reference. Any CH₄ left in the CO₂ stream may be further removed by catalytic partial oxidation in the presence of pure CO₂ stream, thus increasing the purity of the CO₂ product stream which is further pressurized and may be used for enhanced oil recovery (EOR) or geologic storage. Optionally, the CO₂ can be solidified to “dry ice”.

Returning now to the TSA element 220, at the end of Step 3, the bed is saturated with hot CH₄ with small amount of CO₂ remaining on the adsorbent. In Step 4, superheated steam is supplied at high temperature in the range 200° C. to 300° C. and at high pressure in the range 10-30 bar to the bed to remove the rest of the methane and the impurities and the “second” off-gas stream is obtained, which is mixed with the CO₂ free stream cut from the CO₂ removal unit and sent to the SMR unit 106 as a feed. The first and second off-gas stream compositions are adjusted in accordance with the inputs of natural gas and stream to optimize the outputs from the steam methane reformer 106. In Step 5, the bed which is now at a high temperature and saturated with steam, is purged with hot and pure H₂ stream produced in Step 1 after heat exchange. Most of the water in the bed is removed in this step. The purged H₂ stream is sent to the SMR furnace as a fuel or may be supplied as a product. Finally, in Step 6, the hot bed is cooled by supplying pure H₂ produced in Step 1 until the bed is cooled to a temperature of about 40-70° C. to repeat the process.

The second embodiment of the TSA process is described below, in which the adsorbent bed is “swept” with a H₂ stream as shown in FIG. 3.

The shifted gas feed 318 enters the adsorbent bed 301 a in the TSA element 320. The adsorbent bed contains suitable adsorbent material to adsorb the impurities from the feed stream containing H₂ to produce a purer H₂ stream. Any suitable materials such as CO₂, CO, CH₄and H₂O adsorbing zeolites, and the like can be used. In Step 1, the adsorbent bed adsorbs all components except hydrogen, thus a high purity H₂ stream is obtained at high pressure exiting at 322. Upon saturation of the bed which now consists of the impurities CO₂, CO, and CH₄ and H₂O plus H₂ remaining within the bed voids, in Step 2, a portion of the product H₂ is heated to 200° C.-300° C. and is sent to the bed to remove the CO₂ along with the other components. Depending on the amount of H₂ trapped in the bed void volume in Step 1, the CO₂ stream may be mixed with a significant amount of H₂. To decrease the amount of H₂ in the CO₂ stream, the initial portion of the exit stream in Step 2 that contains majority of the gases trapped in the void volume (including H₂), is compressed and recycled to be combined with the feed in Step 1. In Step 2, since the bed is still heating up to the higher temperature, it can be expected that only minor amounts of the adsorbed components are released in the gas stream. Note that the Step 2 is optional and depends on the amount of H₂ trapped in the bed void volume. In Step 3, the H₂ “sweep” is continued to release much of the adsorbed CO₂ at the high temperature. The exiting gas stream is termed as the “first” off-gas stream, which primarily contains H₂ and CO₂ with minor amounts of CH₄ and CO, exits via line 324 to a CO₂ removal process unit. Preferably, the H₂ “sweep” flow rate is adjusted such that the concentration of CO₂ in the “first” off-gas stream is in the range of 30 mol %-95 mol %, or more preferably 60 mol % -95 mol %. Although the CO₂ can be removed from other gaseous components using processes such as amine absorption (e.g., aMDEA) or membrane separation, a cryogenic process is preferred which removes CO₂ from other gases by partial condensation, such as those described in U.S. Patent Application Nos. US 2010/0024476, US 2008/0176174, and US 2008/0173585, incorporated herein by reference. Separate high-purity streams of CO₂, CH₄ and H₂ can be obtained in the cryogenic unit. The CH₄-containing stream is sent as a feed to the SMR, whereas, the stream with majority of H₂ is sent as a fuel to the SMR furnace. The CO₂ product stream, after further pressurization, is sent for enhanced oil recovery (EOR) or geologic storage. Any combustible components left in the CO₂ stream (e.g., CH₄, CO, H₂) may be further removed by catalytic partial oxidation in the presence of pure O₂ stream, thus increasing the purity of the CO₂ stream.

If in the cryogenic CO₂ removal process only partial condensation is used to separate CO₂ from the other components, the vent stream that contains primarily CH₄ and H₂ may be recycled and mixed with the syngas feed to the TSA unit. This configuration would increase the overall H₂ recovery while being less complex. A small purge of the vent stream may be required in this case.

Returning now to the TSA element 320, at the end of Step 3, the bed is saturated with hot H₂ with small amount of CO₂ remaining on the adsorbent. In Step 4, a portion of the H₂ product is supplied at the lower temperature of 40° C.-70° C. to the bed to remove the rest of the CO₂ and the impurities. A portion of the gas exiting from Step 4, which is at a higher temperature, after further heat exchange with a medium such as steam, constitutes the hot H₂ streams for Steps 2 and 3 above. The remaining exit gas from Step 4 is termed as the “second” off-gas stream, which is mixed with the H₂ stream cut from the CO₂ removal unit and sent to the SMR unit as a fuel for the reformer furnace. When the process of the invention is applied to an autothermal reformer (ATR), which does not have a furnace, the H₂ stream is used as a fuel in other applications. At the end of Step 4, the bed is regenerated and cooled to a temperature of about 40-70° C. to repeat the process.

In the first embodiment, the pressure of the first off-gas stream can be adjusted by adjusting the pressure of natural gas feed to the bed. Preferably the TSA element 120 contains six or more beds (four or more beds in the second embodiment as illustrated) claiming the adsorbent that is made out of activated carbon or molecular sieves such as zeolites or silica gel. More than one type of adsorbent may be used in a single bed. Alternatively, the adsorbent material can be fitted in the bed in a structured monolithic format, which would increase the heat and mass transfer rates and decrease the adsorber pressure drop compared to a bed that contains adsorbent in granular or pellet format. One such example of a structured bed is given in the patent application US 2010/0212495 by Corning Inc., incorporated herein by reference. In that example, the sorbent structure comprises a continuous activated carbon body In the form of a flow-through substrate. The temperature of the sorbent structure can be increased by sending a hot gas stream through it and/or by passing a sufficient voltage across the sorbent structure, to provide resistive heating in a process called as electric swing adsorption (ESA). The advantage of heating the structured bed using resistive heating is that the amount of hot sweep gas stream can be reduced or eliminated, thus increasing the concentration of CO₂ in the stream that is sent to a CO₂ removal unit.

EXAMPLE

An example is given for embodiment 1 below for producing H₂ while recycling CH₄ to the SMR as a feed and producing a high concentration CO₂ stream for a CO₂ removal unit in a like manner the embodiment 2 would function to achieve a high purity CO₂ stream. Other variations are possible without departing from the spirit and scope of the invention.

In this example, the syngas flow rats after the low-temperature shift reactor, after removing water by condensation at 40° C., is 7000 kmol/h with the following composition (in mol %):

-   CO₂=19%, H₂=74.5%, CO=0.5%, CH₄=5.5%, H₂O=0.3%, N₂=0.2%. This syngas     mixture at 27 bar is sent to a TSA unit, which consists of 6 beds     packed with BPL carbon beads. Each bed has a dimension of approx.     7.5 m diameter and 5 m length and consists of about 120 tons of the     adsorbent.

Step 1: The shifted gas feed 118 enters an adsorbent bed in the TSA element 120. The adsorbent bed adsorbs all components except hydrogen, thus a high purity H₂ stream (>99 mol %) is obtained at high pressure exiting at 122. This step is continued for 10 min. Upon saturation of the bed which now consists of the impurities CO₂, CO, and CH₄ and H₂O plus H₂ remaining within the bed voids. The H₂ recovery is in the range 90-100%.

Step 2: The saturated bed is pressurized for 1-3 min with natural gas with flow rate in the range 100 kmol/h-2000 kmol/h and at a pressure greater than 20 bar and temperature in excess of 200 to 350° C. The pressure of the natural gas is selected such that the natural gas eventually recycled to the SMR as a feed has the appropriate pressure, matching the pressure of the SMR feed. The temperature of the natural gas is selected such that the bed is hot enough to avoid the condensation of steam that is used in Step 4. The natural gas is heated indirectly to the required temperature using steam or utilizing the heat energy available in other streams, such as streams exiting steps 3, 4 or 5 below. After the bed is pressurized, the valve on the exit line is opened so that the natural gas removes the CO₂ along with the other components from the bed. The initial portion of the exit stream in Step 2 that contains majority of the gases trapped in the void volume (including H₂), is recycled to be combined with the feed in Step 1. This step is continued for 7-9 min.

Step 3: The natural gas “sweep” is continued for 10 min to release much of the adsorbed CO₂ at the high temperature. The exiting gas stream is termed as the “first” off-gas stream, which primarily contains CH₄ and CO₂, exits via line 124 to a CO₂ removal process unit 126. Preferably, the CH₄ “sweep” flow rate is adjusted such that the concentration of CO₂ in the “first” off gas stream is in the range of 30 mol %-60 mol %, or more preferably 50 mol %-60 mol %.

Returning now to the TSA element 120, at the end of Step 3, the bed is saturated with hot CH₄ with small amount of CO₂ remaining on the adsorbent.

Step 4: Superheated steam at flow rate in the range of 100 kmol/h-1000 kmol/h is supplied at high temperature in the range 200° C. to 350° C. and at high pressure in the range 10 bar −30 bar to the bed to remove the rest of the methane and the impurities and the “second” off-gas stream is obtained, which is mixed with the CO₂ free stream cut from the CO₂ removal unit 126 and sent to the SMR unit 106 as a feed. This step is carried out for 10 min.

Step 5: The bed is purged for 10 min with hot and pure H₂ stream exiting Step 6. The temperature of the H₂ stream exiting Step 5 is increased to the range 100° C.-350° C. using steam or some other source of heat available in the process. The purged H₂ stream is sent to the SMR furnace 120 as a fuel or may be supplied as a chemical product or used as a gas turbine fuel.

Step 6: The hot bed is cooled for 10 min by supplying pure H₂ produced in Step 1 with flow rate in the range 100 kmol/h-2000 kmol/h until the bed is cooled to a temperature of about 20° C.-100° C., preferably, 40° C.-70° C. to repeat the process.

Note that the cycle time in the above process is taken as 10 min. However, it should be noted that the cycle time is a function of the syngas flow rate, composition, adsorbent bed configuration, nature of the adsorbent and it can vary between 30 sec and 30 min or longer.

Also note that in FIGS. 2 and 3, the streams are shown to enter from the top of the bed; however, any combination of flows, such as co-current and counter-current is possible. This process can be applied as a retrofit to a “new style” SMR plant that would replace the conventional PSA unit with a combination of TSA and CO₂ removal unit described here. This process can also be applied to the ATR hydrogen plants. Since the ATR does not have a furnace like SMR, the H₂ that has been used for sweeping and cooling steps will be used as a fuel or product elsewhere. 

What is claimed:
 1. A process for producing hydrogen and removing CO₂ in a steam methane reformer (SMR) process wherein the improvement comprises a. passing shifted syngas from a SMR to a temperature swing adsorption (TSA) unit b. taking an off-gas which contains primarily CH₄ and CO₂ to a CO₂ removal unit wherein the recovered CO₂ can be sequestered or used for enhanced oil recovery (EOR) c. taking a second off-gas containing CH₄ wherein the stream off gas and first off gas of reduce CO₂ are mixed and returned to the steam methane reformer; and d. recovering a purified H₂ product from the TSA unit for use as a chemical product, fuel gas or an input to the steam methane reformer furnace or a combination of these.
 2. The process according to claim 1 wherein the TSA cycle is operated at a temperature of 40° C. psi to 350° C. and a pressure of 10 bar to 40 bar.
 3. The process according to claim 1 wherein the removed CO₂ is sequestered or used for EOR.
 4. The process according to claim 2 wherein the H₂ is 200° C.-300° C. prior to entering the CO₂ removal bed.
 5. The process according to claim 5 wherein the H₂ flow rate to sweep CO₂ ranges from 30 vol. %.-60 vol. %.
 6. A process for producing hydrogen and removing CO₂ in a steam methane reforming process wherein the improvement comprises a. passing shifted syngas from a SMR to a autothermal reformer (ATR) b. taking an off-gas which contains primarily CH₄ and CO₂ to a CO₂ removal unit wherein the recovered CO₂ can be sequestered or used as an input to the steam methane reformer to assist in adjusting in the water gas shift reaction in the stream methane reformer c. taking a second off-gas containing CH₄ wherein the stream off gas and first off gas of reduce CO₂ are mixed and returned to the steam methane reformer; and d. recovering a purified H₂ product from the ATR unit for use as a chemical product, fuel gas or an input so the steam methane reformer furnace or a combination of these.
 7. The process according to claim 1 wherein the TSA cycle is operated at a temperature of 40° C. psi to 300° C. psi and a pressure of 10 to 30 bar.
 8. The process according to claim 7 wherein the removed CO₂ is sequestered.
 9. The process according to claim 7 wherein the removed CO₂ is used to adjust the water gas shift reaction.
 10. The process according to claim 7 wherein the H₂ is 200° C.-300° C. prior to entering the CO₂ removal bed.
 11. The process according to claim 7 wherein the H₂ flow rate to sweep CO₂ ranges from 30 vol. %-60 vol. %.
 12. A multi-step process for operating a temperature swing adsorption (TSA) apparatus which comprises: Step 1, feeding a shifted gas from a steam methane reformer (SMR) to the adsorbent bed adsorbs to remove gases components other than H₂ to produce a high purity H₂ stream at high pressure exiting the apparatus and upon saturation of the bed which contains impurities CO₂, CO, and CH₄ and H₂O plus H₂ remaining within the bed voids, thereafter; Step 2, introducing hot natural gas at high pressure greater than 20 bar and temperatures in excess of 200 to 300° C. to remove the CO₂ along with the other components and wherein the CO₂ stream may be mixed with a significant amount of H₂ so as to decrease the amount of H₂ in the CO₂ stream so that the gas stream contains majority of the gases trapped in the void volume, including H₂, is compressed and recycled to be combined with the feed in Step 1, thereafter; Step 3, continuing the natural gas “sweep” to release much of the adsorbed CO₂ at the high temperature and wherein the exiting gas stream contains CH₄ and CO₂, is sent to a CO₂ removal process unit and wherein the bed is saturated with hot CH₄ with small amount of CO₂ remaining on the adsorbent, thereafter; Step 4, superheated steam is supplied at high temperature in the range 200° C. to 300° C. and at high pressure in the range 10-30 bar to the bed to remove the remaining methane and the impurities and this second off-gas stream is obtained, which is mixed with the CO₂ free stream cut from the CO₂ removal unit and cycled to a SMR unit as a feed and, thereafter; Step 5, the bed, which is now at a high temperature, and saturated with steam, is purged with hot and pure H₂ stream produced in Step 1 after heat exchange to remove H₂ and H₂O, and thereafter; Step 6, the hot bed is cooled by supplying pure H₂ produced in Step 1 until the bed is cooled to a temperature of about 40-70° C. to repeat the process the cycling process.
 13. A process to operate a temperature swing adsorption (TSA) apparatus in a stream methane reformer process (SMR) wherein an H₂ sweep gas is used, the process comprising: Step 1 wherein shifted gas from the SMR is fed to adsorbing beds capable of adsorbing impurities other than H₂ and wherein high pressure H₂ exits to adsorption bed until bed saturation with CO₂, CO, and CH₄ and H₂O plus H₂ remaining and, thereafter; Step 2, a portion of the purified H₂ is heated to 200° C.-300° C. and is sent to the bed to remove the CO₂, CO, CH₄ impurities and, thereafter; Step 3, the H₂ gas injection is continued to release the adsorbed CO₂ at the high temperature wherein the exiting gas stream primarily contains H₂ and CO₂ with minor amounts of CH₄ and CO is sent to a CO₂ removal process unit and, thereafter; Step 4, a portion of the H₂ product is supplied to the lower temperature of 40° C.-70° C. to the bed to remove the rest of the CO₂ and the impurities and a portion of the gas exiting from Step 4, which is at a higher temperature, after further heat exchange with a medium such as steam, constitutes the hot H₂ as an off-gas stream, which is mixed with the H₂ stream cut from the CO₂ removal unit and sent to the SMR unit as a fuel for the reformer furnace and to permit the process to cycle again. 